Development of a compositional model fully coupled with geomechanics and its application to tight oil reservoir simulation

Abstract

Tight oil reservoirs have received great attention in recent years as unconventional and promising petroleum resources; they are reshaping the U.S. crude oil market due to their substantial production. However, fluid flow behaviors in tight oil reservoirs are not well studied or understood due to the complexities in the physics involved. Specific characteristics of tight oil reservoirs, such as nano-pore scale and strong stress-dependency result in complex porous medium fluid flow behaviors. Recent field observations and laboratory experiments indicate that large effects of pore confinement and rock compaction have non-negligible impacts on the production performance of tight oil reservoirs. On the other hand, there are approximations or limitations for modeling tight oil reservoirs under the effects of pore confinement and rock compaction with current reservoir simulation techniques. Thus this dissertation aims to develop a compositional model coupled with geomechanics with capabilities to model and understand the complex fluid flow behaviors of multiphase, multi-component fluids in tight oil reservoirs. MSFLOW_COM (Multiphase Subsurface FLOW COMpositional model) has been developed with the capability to model the effects of pore confinement and rock compaction for multiphase fluid flow in tight oil reservoirs. The pore confinement effect is represented by the effect of capillary pressure on vapor-liquid equilibrium (VLE), and modeled with the VLE calculation method in MSFLOW_COM. The fully coupled geomechanical model is developed from the linear elastic theory for a poro-elastic system and formulated in terms of the mean stress. Rock compaction is then described using stress-dependent rock properties, especially stress-dependent permeability. Thus MSFLOW_COM has the capabilities to model the complex fluid flow behaviors of tight oil reservoirs, fully coupled with geomechanics. In addition, MSFLOW_COM is validated against laboratory experimental data, analytical solutions and results of a commercial simulator before conducting numerical studies. The numerical studies demonstrate the effect of capillary pressure on VLE, and further on production performance. The significant effect of capillary pressure on VLE leads to the suppression of bubble-point pressure and more light components dissolved in the oil phase. Consequently it is observed that there is smaller gas saturation, larger mole fractions of light components, and faster pressure decreasing at reservoir conditions; meanwhile less gas and more oil are produced at surface. The substantial decrease in reservoir pore pressure results in a large increase of effective stress, which induces the changes of rock properties and influences the production performance. The stress-induced degradation of permeability undermines the production performance, and the geomechanical effect on the permeability of natural fractures is mainly responsible for the undermined production performance. The reduction of pore size due to the geomechanical effect could increase the capillary pressure, which enlarges the influence of capillarity on VLE and further suppresses bubble-point pressure. On the other hand, the effect of capillary pressure on VLE influences the fluid flow and therefore influences the effective stress through the flow-stress coupling process. Thus the interaction between pore confinement and rock compaction can be modeled with MSFLOW_COM, and illustrated through numerical studies. This research provides a three-dimensional numerical tool for accurately modeling porous and fractured tight oil reservoirs. The developed simulator is able to assist scientists and engineers to study and understand the complex multiphase, multi-component fluid flow behaviors in tight oil reservoirs.